The present invention relates to a process for removing acid gases from natural gas and other gas streams. In particular, it relates to a process for increasing the selectivity and capacity for hydrogen sulfide removal from a natural gas stream using aqueous amine absorbents.
A number of different technologies are available for removing acid gases such as carbon dioxide, hydrogen sulfide, carbonyl sulfide. These processes include, for example, chemical absorption (amine/alkanolamine), physical absorption (solubility, e.g., organic solvent, ionic liquid), cryogenic distillation (Ryan Holmes process), and membrane system separation. Of these, amine separation is a highly developed technology with a number of competing processes in hand using various amine/alkanolamine sorbents such as monoethanolamine (MEA), diethanolamine (DEA), triethanolamine (TEA), N-methyldiethanolamine (MDEA), diisopropylamine (DIPA), diglycolamine (DGA), 2-amino-2-methyl-1-propanol (AMP) and piperazine (PZ). Of these, MEA, DEA, and MDEA are the ones most commonly used. The acid gas scrubbing process using an amine in the purification process usually involves contacting the gas mixture countercurrently with an aqueous solution of the amine in an absorber tower. The liquid amine stream is then regenerated by desorption of the absorbed gases in a separate tower with the regenerated amine and the desorbed gases leaving the tower as separate streams. The various gas purification processes which are available are described, for example, in Gas Purification, Fifth Ed., Kohl and Neilsen, Gulf Publishing Company, 1997, ISBN-13: 978-0-88415-220-0.
It is often necessary or desirable to treat acid gas mixtures containing both CO2 and H2S so as to remove the H2S selectively from the mixture while minimizing removal of the CO2. While removal of CO2 may be necessary to avoid corrosion problems and provide the required heating value to the consumer, selective H2S removal may be necessary or desirable. Natural gas pipeline specifications, for example, set more stringent limits on the H2S level than on the CO2 since the H2S is more toxic and corrosive than CO2: common carrier natural gas pipeline specifications typically limit the H2S content to 4 ppmv with a more lenient limitation on the CO2 at 2 vol %. Selective removal of the H2S may enable a more economical treatment plant to be used and selective H2S removal is often desirable to enrich the H2S level in the feed to a sulfur recovery unit.
The reaction kinetics with hindered amine sorbents allow H2S to react more rapidly with the amine groups of the sorbent to form a hydrosulfide salt in aqueous solution, but under conditions of extended gas-liquid contact where equilibrium of the absorbed sulfide species with CO2 is approached, carbon dioxide can displace hydrogen sulfide from the previously absorbed hydrosulfide salt since carbon dioxide is a slightly stronger acid in aqueous solution than hydrogen sulfide (ionization constant for the first ionization step to H+ and HCO3− is approximately 4×10−7 at 25° C. compared to 1×10−7 for the corresponding hydrogen sulfide ionization) so that under near equilibrium conditions, selective H2S removal becomes problematical, presenting a risk of excessive H2S levels in the effluent product gas stream.
An improvement in the basic amine process involves the use of sterically hindered amines. U.S. Pat. No. 4,112,052, for example, describes the use of hindered amines for nearly complete removal of acid gases including CO2 and H2S. U.S. Pat. Nos. 4,405,581; 4,405,583; 4,405,585 and 4,471,138 disclose the use of severely sterically hindered amine compounds for the selective removal of H2S in the presence of CO2. Compared to aqueous MDEA, severely sterically hindered amines lead to much higher selectivity at high H2S loadings. Amines described in these patents include BTEE (bis(tertiary-butylamino)-ethoxy-ethane synthesized from tertiary-butylamine and bis-(2-chloroethoxy)-ethane as well as EEETB (ethoxyethoxyethanol-tertiary-butylamine) synthesized from tertiary-butylamine and chloroethoxyethoxyethanol). U.S. Pat. No. 4,894,178 indicates that a mixture of BTEE and EEETB is particularly effective for the selective separation of H2S from CO2. U.S. Pat. No. 8,486,183 describes the preparation of alkoxy-substituted etheramines as selective sorbents for separating H2S from CO2.
The use of hydroxyl-substituted amines (alkanolamines) such as those mentioned above has become common since the presence of the hydroxyl groups tends to improve the solubility of the absorbent/acid gas reaction products in the aqueous solvent systems widely used, so facilitating circulation of the solvent through the conventional absorber tower/regeneration tower unit. This preference may, however, present its own problems in certain circumstances. A current business driver is to reduce the cost to regenerate and to recompress acid gases prior to sequestration. For natural gas systems, the separation of the acid gases can occur at pressures of about 4,800-15,000 kPaa (about 700-2,200 psia), more typically from about 7,250-8,250 kPaa (about 1050-1200 psia). While the alkanolamines will effectively remove acid gases at these pressures, the selectivity for H2S removal can be expected to decrease markedly both by direct physisorption of the CO2 in the liquid solvent and by reaction with the hydroxyl groups on the amine compound. Although the CO2 reacts preferentially with the amino nitrogen, higher pressures force reaction with the oxygens and under the higher pressures, the bicarbonate/hemicarbonate/carbonate reaction product(s) formed by the reaction at the hydroxyl site is stabilized with a progressive loss in H2S selectivity with increasing pressure. This effect can be perceived, for example, with MDEA (N-methyldiethanolamine). For example, 5M MDEA in aqueous solution does not absorb carbon dioxide under ambient conditions, but will form a hydrosulfide salt at the nitrogen. However, H2S/CO2 selectivity significantly reduces at high CO2 pressure presumably due to O-carbonation of hydroxyl groups:

A similar trend is observed with the secondary aminoether, ethoxyethoxyethanol-t-butylamine (EEETB): at low pressures, this absorbent offers H2S selectivity over CO2 based on a faster reaction with the hindered secondary amine group although a significant amount of CO2 can be absorbed by the hydroxyl group which has low affinity to H2S. At higher pressures, however, the reaction yield of O-carbonation increases, suppressing the H2S/CO2 selectivity achieved by the hindered secondary amine:

U.S. 2015/0027055 describes an absorbent system that can selectively absorb H2S from gas mixtures that also contain CO2 and that can be regenerated at high pressure (greater than 10 bara) while maintaining very low CO2 solubility. The absorbent may include capped alkanolamines, i.e., alkanolamines in which one or more of the hydroxyl groups have been capped or converted into ether groups, including N-(2-methoxyethyl)-N-methyl-ethanolamine (MDEA-(OMe), Bis-(2-methoxyethyl)-N-methylamine (MDEA-(OMe)2), 2-amino-prop-1-yl methyl ether (AP-OMe), 2-methyl-2-amino-prop-1-yl methyl ether (AMP-OMe), 2-N-methylamino-prop-1-yl methyl ether (MAP-OMe), 2-N-methylamino-2-methyl-prop-1-yl methyl ether (MAMP-OMe), 2-N-ethylamino-2-dimethyl-prop-1-yl methyl ether, (EAMP-OMe), 2-(N,N-dimethylamino)-ethyl methyl ether (DMAE-OMe), and Methoxyethoxyethoxyethanol-t-butylamine (M3ETB). The absorbent may also include more basic sterically hindered secondary and tertiary amines, including guanidines, amidines, biguanides, piperidines, piperazines, and the like, such as tetramethylguanidine, pentamethylguanidine, 1,4-dimethylpiperazine, 1-methylpiperidine, 2-methylpiperidine, 2,6-dimethylpiperidine, their hydroxyalkyl, e.g., hydroxyethyl derivatives, and mixtures thereof.
In spite these advancements in absorbents, there still remains a need for an absorption system that maintains a high selectivity and absorption capacity for H2S over a wide range of loadings.